Various types of rotary drill bits have been used to form wellbores or boreholes in downhole formations. Such wellbores are often formed using a rotary drill bit attached to the end of a generally hollow, tubular drill string extending from an associated well surface. Rotation of a rotary drill bit progressively cuts away adjacent portions of a downhole formation using cutting elements and cutting structures disposed on exterior portions of the rotary drill bit. Examples of rotary drill bits include fixed cutter drill bits or drag drill bits, impregnated diamond bits and matrix drill bits. Various types of drilling fluids are generally used with rotary drill bits to form wellbores or boreholes extending from a well surface through one or more downhole formations.
Various types of computer based systems, software applications and/or computer programs have previously been used to simulate forming wellbores including, but not limited to, directional wellbores and to simulate performance of a wide variety of drilling equipment including, but not limited to, rotary drill bits which may be used to form such wellbores. Some examples of such computer based systems, software applications and/or computer programs are discussed in various patents and other references listed on Information Disclosure Statements filed during prosecution of this patent application.
Various types of rotary drill bits, reamers, stabilizers and other downhole tools may be used to form a borehole in the earth. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, PDC drill bits, matrix drill bits, roller cone drill bits, rotary cone drill bits and rock bits used in drilling oil and gas wells. Cutting action associated with such drill bits generally requires weight on bit (WOB) and rotation of associated cutting elements into adjacent portions of a downhole formation. Drilling fluid may also be provided to perform several functions including washing away formation materials and other downhole debris from the bottom of a wellbore, cleaning associated cutting elements and cutting structures and carrying formation cuttings and other downhole debris upward to an associated well surface.
Some prior art rotary drill bits have been formed with blades extending from a bit body with a respective gage pad disposed proximate an uphole edge of each blade. Gage pads have been disposed at a positive angle or positive taper relative to a rotational axis of an associated rotary drill bit. Gage pads have also been disposed at a negative angle or negative taper relative to a rotational axis of an associated rotary drill bit. Such gage pads may sometimes be referred to as having either a positive “axial” taper or a negative “axial” taper. See for example U.S. Pat. No. 5,967,247. The rotational axis of a rotary drill bit will generally be disposed on and aligned with a longitudinal axis extending through straight portions of a wellbore formed by the associated rotary drill bit. Therefore, the axial taper of associated gage pads may also be described as a “longitudinal” taper.
The phenomenon of bit walk, particularly when drilling a directional wellbore, has been observed in the oil and gas industry for many years. It is widely accepted that roller cone drill bits will generally have a tendency to “walk right” relative to a longitudinal axis being formed by the associated roller cone drill bit. It has also been widely accepted that fixed cutter drill bits, sometimes referred to as “PDC bits,” may often have a tendency to walk left relative to a longitudinal axis of a wellbore formed by an associated fixed cutter drill bit.
Some prior models used to simulate drilling wellbores often failed to explain why fixed cutter drill bits walk right and may even have very large right walk rates under some specific conditions. For example, prior field reports have noted that some fixed cutter drill bits have a strong tendency to walk right when building angle during forming a directional wellbore segment.
For many downhole drilling conditions, bit walk and particularly excessive amounts of bit walk are not desired. Bit walk may generally increase drag on an associated drill string while forming a directional wellbore. Excessive amounts of bit walk may also result in damage to an associated drill string and/or “sticking” of the drill string with adjacent portions of a wellbore. Excessive amounts of bit walk may also result in forming a tortuous wellbore which may create problems while installing an associated casing string or other well completion problems. In many drilling applications, bit walk should be avoided and/or substantially minimized whenever possible.